The present invention relates to an integrated air separation and power generation process. More specifically, the present invention relates to a process for separating at least oxygen and nitrogen from air and integrating the use of oxygen and nitrogen into a process for efficiently generating electrical power.
Cogeneration involves using a single fuel source to simultaneously produce, in the same facility, thermal energy, usually in the form of steam, and electric energy. Since the Public Utility Regulatory Policy Act of 1978, owners of cogeneration facilities have been given a financial incentive to sell excess electrical power to utility companies, while utilities are encouraged to purchase that electrical power. Consequently, there has been a continuing effort to improve the energy efficiency of cogeneration plants, particularly in the United States. Moreover, the rising and volatile costs of natural gas have increased the economic incentive for many cogeneration plants to use other fuel sources, such as coal, for example.
Many cogeneration processes use an integrated, high-efficiency combined cycle to increase efficiency. Typically, a combined cycle is a steam turbine (i.e., Rankine-cycle) thermodynamically coupled with a gas turbine (i.e., Brayton-cycle). Steam and gas turbine combined cycle systems are often used where natural gas is the fuel source because natural gas tends to have a lower concentration of impurities that can cause hot corrosion, fouling and rapid deterioration in the gas turbine parts, particularly gas turbine blade surfaces. Therefore, historically, use of high-efficiency steam/gas combined cycle systems has been discouraged where coal is used as a fuel source due to the various impurities in coal that can cause gas turbine corrosion. Consequently, when using a steam/gas combined cycle in a coal combustion cogeneration process, it is important to limit the gas turbine""s exposure to flue gas impurities and temperatures significantly exceeding the maximum admissible value. The maximum admissible temperature for a gas turbine is primarily dictated by the gas turbine""s materials of construction and its other operating conditions and is typically in a range of from about 1000xc2x0 C. to about 1450xc2x0 C. Limiting exposure to flue gas impurities and higher temperatures will help forestall significant corrosion problems with the gas turbine and, thereby, keep equipment maintenance costs down.
U.S. Pat. No. 4,116,005 by Willyoung proposes using a fluidized combustor bed containing sulfur-sorbing particles that are fluidized by a gas turbine""s air exhaust, at about atmospheric pressure, which also provides an O2 source for the coal""s combustion. However, Willyoung""s proposed system fails to further enhance the inherent efficiency of using a steam/gas combined cycle in a cogeneration process. Also, Willyoung""s modification of the combustion chamber with a fluidized bed requires significant expense and upkeep for limiting gas turbine corrosion.
Another factor challenging many coal fired cogeneration processes are gaseous emissions into the atmosphere, particularly nitrogen oxides (NOx), such as nitrogen oxide (NO), nitrogen dioxide (NO2) and nitrous oxide (N2O), sulfur oxides (SOx), such as sulfur dioxide (SO2) and sulfur trioxide (SO3), and carbon dioxide (CO2). Some global warming proponents relate excess N2O and CO2 emissions to climatological change. Also, NOx emissons, such as NO or NO2, in sufficient concentration, can be toxic to health and the environment. Additionally, SOx emissions, in sufficient concentration, can contribute to the production of xe2x80x9cacid rain,xe2x80x9d which can have a detrimental effect on various plant and aquatic life. Thus, it is possible that many or all of these gases could become more stringently regulated, at least in certain market-developed countries or regions, such the United States, Canada, Japan and Europe. Consequently, this prospect of increasing regulatory stringency for some or all gaseous emissions that are typically coal combustion by-products has made coal-fueled cogeneration processes less attractive from an operational cost standpoint.
For instance, various countries, including, among others, France, Germany, the United Kingdom, Australia, the United States, Canada and Japan have agreed to seek internal approval and adoption, within their respective jurisdictions, of the Kyoto Protocol. The Kyoto Protocol ensued from the United Nations Framework Convention on Climate Change, held in December, 1997 at Kyoto, Japan. Under the Kyoto Protocol each participant agreed in principle to xe2x80x9cimplement and/or further elaborate policies and measures in accordance with its national circumstancesxe2x80x9d to, among other things, enhance energy efficiency and protect reservoirs of certain atmospheric gases not controlled by the Montreal Protocol (e.g., CO2).
Generally, under the Kyoto Protocol the participating countries agreed to limit emissions of greenhouse gases specified under the Protocol, including CO2, methane (CH4), N2O, hydrofluorocarbons (HFCs), perfluorocarbons (PFCs) and sulfur hexafluoride (SF6), as well as work towards reducing the overall emissions of these gases by at least 5 percent below 1990 levels in the target period of 2008 to 2012. To date, no legislative amendments to the U.S. Clean Air Act Amendments of 1990 (CAAA) have been passed that would require facilities operating in the U.S. to comply with the Kyoto Protocol greenhouse gas emissions target. Nonetheless, the 1996-2000 U.S. administration has made a policy decision to promote voluntary compliance with the Kyoto Protocol. Accordingly, companies operating in the U.S. that have significant CO2 emissions have been encouraged to voluntarily work towards the Kyoto Protocol""s target level for the greenhouse gases specified. Also, if good progress towards the Protocol""s goals is not shown, it is possible that some further amendments to the CAAA could flow from the Kyoto Protocol. CAAA amendments conforming with the Kyoto Protocol could also be motivated if models are developed to more definitively measure and predict the extent of global climate changes based on current and projected gaseous emissions. Thus, limiting the gaseous emissions, particularly from coal-fueled power generation plants, while maintaining an energy efficient power generation process is becoming a more important commercial objective.
For example, U.S. Pat. No. 5,937,652 by Abdelmalek proposes to produce energy more efficiently and reduce CO2 emissions from a combined coal gasification and synthesis gas (i.e., a carbon monoxide (CO) and hydrogen gas (H2) mixture) combustion process. The coal gasification step is conducted under an oxygen (O2) free atmosphere, while using CO2 and steam as oxidants for the coal fuel. The heat from the coal/CO2 gasification reaction is used to produce steam for driving a steam turbine/generator that produces electricity. Also, Abdelmalek separates CO2 from sulfur dioxide (SO2) and other gases discharged from a boiler using a cyclone separator system disclosed in U.S. Pat. Nos. 5,403,569 and 5,321,946.
Abdelmalek indicates that the process has a higher efficiency because the gasification reaction is run without O2, while the separated CO2, which is recycled back to the gasification chamber for reacting with coal, produces a nitrogen (N2) free synthesis gas, namely a CO and H2 mixture. This CO/H2 mixture is then combusted with O2 to generate heat. According to Abdelmalek, the gross heat value of his combined coal gasification, where little to no O2 is present, and synthesis gas combustion process, where CO and H2 are reacted with O2 to produce the principle heat, is 20% greater versus conventional coal combustion processes, where coal is burned using O2 as a principle oxidant. Abdelmalek also contends that his process reduces CO2 emissions by 20%. Moreover, Abdelmalek teaches that the combustion reaction chemistry, particularly where coal is a fuel source (e.g., coal+O2), makes conventional combustion type reactions inherently limited in the extent to which they can be made any more efficient, even in the context of a cogeneration process. Consequently, Abdelmalek fails to disclose how to improve the efficiency of a cogeneration process primarily using direct combustion of a fuel, such as coal, and/or reduce CO2 emissions to the atmosphere, as well as other gaseous emissions, such as nitrous oxide (NO), nitrous oxide (N2O) and nitrogen dioxide (NO2), (collectively called NOx) and/or sulfur dioxide (SO2) and sulfur trioxide (SO3) (collectively called SOx).
Another example of producing CO2 and energy from the same process and fuel source is disclosed in U.S. Pat. No. 6,047,547 by Heaf. Heaf proposes a portable integrated cogeneration system that produces electric power, steam and liquid CO2 and other products necessary for producing and filling bottled or canned beverage products. Specifically, Heaf proposes using a combustion engine generator (CEG) to produce electric power and a combustion powered water boiler to produce steam. A CO2 recovery unit connected with the CEG and water boiler receives exhaust gases from the CEG and water boiler for separating and recovering CO2 from the exhaust gases and a compressor is used to liquefy the recovered CO2. Heaf suggests that his cogeneration system can produce large quantities of CO2 from one and preferably both the CEG and the combustion powered water boiler. But, with respect to operating efficiency, Heaf only suggests that his integrated cogeneration system xe2x80x9cis efficient and saves costs when incorporated into a beverage production facility.xe2x80x9d But Heaf fails to quantify the efficiency of his proposed cogeneration process. Moreover, Heaf fails to disclose any means or methods for improving operating efficiency in combustion powered boiler systems used outside the context of a beverage production and bottling facility.
U.S. Pat. No. 5,067,837 by Rathbone et al is directed to an air separation process in combination with a chemical process. A nitrogen stream produced in the air separation unit is pressurized to at least 5 atmospheres and heated via heat exchange with a hot fluid produced in the chemical process. The heated nitrogen is then expanded in an expansion turbine to produce work. The nitrogen exiting the turbine is: (a) used to heat the oxygen or fuel in a heat exchanger; (b) vented to the atmosphere; or (c) used to raise steam in a steam generator. However, Rathbone suggests using O2 in a partial oxidation type reaction where purified natural gas is reacted with O2 to form a synthesis gas with a desired CO content (i.e., a gasification process). Also, Rathbone suggests using N2 heated only with a hot synthesis gas produced from a gasification process, rather than a combustion process that oxidizes the fuel more completely to produce a flue gas primarily comprising CO2 and, where natural gas is the fuel, CO2 and water vapor, among other reaction products. Moreover, Rathbone fails to disclose any means or methods for improving operating efficiency in combustion powered boiler systems used outside the context of a natural gas gasification process.
U.S. Pat. No. 5,709,077 (Jan. 20, 1998), U.S. Pat. No. 5,715,673 (Feb. 10, 1998), U.S. Pat. No. 5,956,937 (Sep. 28, 1999) and U.S. Pat. No. 5,970,702 (Oct. 26, 1999), all by Beichel and assigned to Clean Energy Systems, Inc. (Sacramento, Calif.), describe a power generation system in which high pressure fuel and high pressure O2 are burned in a gas generator to generate high temperature gas. The combustion temperature is controlled by cooling water injected into a gas mixing chamber in the gas generator. The high pressure, high temperature steam/CO2 mixture from the gas generator is passed through a series of three turbines with inter-turbine reheaters between the turbines. The gas is condensed and water is recycled to the gas generator.
U.S. Pat. No. 5,680,764 (Oct. 28, 1997) by Viteri, also assigned to Clean Energy Systems, Inc., describes a power generation system where pressurized fuel and O2 are fed to a gas generator to achieve complete combustion and maximum temperature hot gases (6,500xc2x0 R (6,040xc2x0 F., 3,300xc2x0 C.). The hot gases are diluted with water to reduce the temperature to 2,000xc2x0 R (1,540xc2x0 F., 840xc2x0 C.). When hydrogen is used as a fuel, the drive gas is steam and when a light hydrocarbon is used, the drive gas is steam and CO2. The hot gas is expanded in a turbine for powering a vehicle and then condensed into water to complete the Rankine cycle. About 75% of the water is recirculated to the gas generator. In one embodiment, the Rankine cycle is replaced with Otto and Diesel thermal cycles to eliminate the need for a condenser and recirculating water system. Depending on the fuel used, low temperature steam (hydrogen fuel) or steam/CO2 (hydrocarbon fuel) gases are recirculated as the working fluid in the Otto and Diesel embodiment.
U.S. Pat. No. 6,170,264 (Jan. 9, 2001), also by Viteri and assigned to Clean Energy Systems, Inc., describes the same process as U.S. Pat. No. 5,680,764 and further suggests using an air separation plant. Enriched O2 is used in a combustion device and enriched N2 is vented to the atmosphere. In one embodiment, CO2 is sequestered into deep underground or undersea locations.
Typically, the overall energy producing efficiency of most coal-fired cogeneration processes is in a range from about 25% to about 35%. Consequently, there is a need for an integrated cogeneration process for producing electrical power and thermal energy with improved efficiency. Preferably, the total efficiency of an improved cogeneration process would be greater than about 40% and, more preferably, greater than about 50%.
Also, the more energy efficient cogeneration process should have a method for reducing corrosion effects on gas turbines used in steam turbine/gas turbine combined cycle, while being adaptable to incorporating, as desired, a system for reducing and/or eliminating various gaseous emissions, such as CO2, NOx and/or SOx, to the atmosphere.
According to the invention, there is provided an integrated air separation and power generation process, comprising the steps of:
(a) introducing an O2/N2 source to an air separation unit;
(b) separating the O2/N2 source into at least an O2-enriched gaseous stream and an N2-enriched gaseous stream;
(c) introducing at least a portion of the O2-enriched gaseous stream, having a pressure of at least about 3 bars (300 kPa), and fuel to a combustor to produce a combustion mixture;
(d) burning the combustion mixture to produce at least a flue gas;
(e) injecting steam into the combustor, before, during and/or after the combustion mixture burning step, to produce a modified combustion mixture of at least steam and flue gas;
(f) generating power by introducing the modified combustion mixture exiting the combustor into a first power generating means;
(g) heating at least a portion of the N2-enriched gaseous stream, having a pressure of at least 3 bars (300 kPa); and
(h) generating power by introducing the heated N2-enriched gaseous stream into a second power generating means.